Method for determining liquid production from a well

ABSTRACT

A method for determining the liquid flow in a pipe having turbulent flow, for example, two-phase flow wherein the dynamic pressure fluctuations are measured, and converted to a useful signal. The root mean square of the signal is obtained and integrated over a specific time interval to obtain the liquid flow in the pipe.

Hawaii Patterson et al.

[ 1 Sept. 30, 1975 [54] METHOD FOR DETERMINING LIQUID 3.643.740 2/1972Kelley 166/314 X PRODUCTION FROM A WELL 1653.717 4/1972 Rich Ct 211.166/314 X 3,705,532 12/1972 Hubby 166/314 X [75] inventors: Maurice M.Patterson, Houston;

$358 C. Sheffield, 8611211113. 13011] Of ex 150,656 I 12/1962 U.S.S.R.73/194 B [73] Assignee: Shell Oil Company, Houston, Tex.

1221 Filed: 1974 Primary E.\'aminerStephen J. Novosad [21] Appl. No.:494,581

Related US. Application Data [62] Division of Ser. No. 356.650. May 2,1973. Pat. No. [57] ABSTRACT v A method for determining the liquid flowin a pipe [s7] U S Cl 166/250 166/314. 73 having turbulent flow, forexample, two-phase flow 5; EzlB 66 wherein the dynamic pressurefluctuations are mea- {581 Field 314 sured, and converted to a usefulsignal. The root mean fifl square of the signal is obtained andintegrated over a specific time interval to obtain the liquid flow inthe [56] References Cited pipe UNITED STATES PATENTS 3 Claims, 8 DrawingFigures $219,107 11/1965 Brown. Jr. et a1. 166/250 L i 11 DYNAMICPRESSURE TRANSDUCER COUPLER I8 I IN TEGRA TOR ,7 I5 VAR/A BLE 5 RMS TIMECONVERSION CONSMN T5 79 STRIP CHART RECORDER U.S. Patent Sept. 50,1975Sheet1of4 3,908,761

47 DYNAMIC PRESSURE 1 TRANSDUCER COUPLER l /74 F /G.7

58 INTEGRATOR (VAR/ABLE s RMS T/ME CONVERSION CONSTANTS) 79 STRIP CHARTRECORDER PRODUCT/ON (0/L+WATER), /0 8 u 0 I I g 1600 0 80 5 M00 PSMOUTPUT, mv

c I l l 0 50 I00 I50 200 250 300 PSM READING, mv

US. Patent Sept. 30,1975 Sheet 2 of4 3,908,761

FIG.2 TURBULENT ENERGY 1/2 D/A. L/NE TOTAL RMS ENERGY, mv

FIG. 3 TURBULENCE SPECTRA 400 (AMPLITUDE ONLY) 1/2 D/A. LINE FOR NR5FROM I0 000 T0 50000 FILTER CENTER FREQUENCY, HZ

U.S. Patent Sept. 30,1975 Sheet 3 of4 3,908,761

TIME (SECONDS) US. Patent Sept. 30,1975 Sheet4 0f4 3,908,761

\WQZOUMMQ NSC my R w m w m N m GE METHOD FOR DETERMINING LIQUIDPRODUCTION FROM A WELL CROSS-REFERENCE This is a division of applicationSer.-No..356,650, filed May 2, 1973 now US. Pat. No. 3.834,227.

BACKGROUND OF THE INVENTION The present invention relates to a methodfor deter mining the liquid flow from a well and particularly the liquidflow in an oil well having turbulent slug or twophase flow. In a largeportion of the producing oil wells, some means of artificiallifting isused. For example, the well can be pumped by either a rod driven pump orhydraulic pump or a gas lift system can be used. In the case of gaslift, gas is transmitted down the well under high pressure and used tolift the oil to the surface. In a gas lift well the oil flows to thesurface in the form of discrete slugs separated by gas. Of course, inthe case of a pumped well, the oil is pumped directly to the surface ina semi-continuous flow until the well is pumped dry at which point thepump will either pump air or be shut down.

In all of the above-described artificial lifting systems, it isdesirable to know the quantity of liquid actually produced at thesurface. For example, in the case of a gas lift well, if too much gas istransmitted to the bottom, the gas will tend to disperse into the liquidphase and reduce the quantity of the oil lifted to the surface.Likewise, if too little gas is transmitted to the bottom of the hole,the quantity of oil lifted to the surface will be smaller. Thus. theadjustment of the gas lift system for the optimum flow of gas is highlydesirable to obtain the maximum efficiency of the system while producingthe maximum amount of oil. Similarly, in the case of pumped wells, it isdesirable to know when the well has been pumped dry so that the pump canbe secured until the well again fills with liquid. This, of course,conserves the. energy required for driving the pumping means andimproves the efficiency.

BRIEF DESCRIPTION OF THE INVENTION The present invention is based on thediscovery that the variation in the fluid pressure during turbulent flowcan be correlated with the total liquid flow in a slug or two-phaseflow. Turbulent flow occurs at Reynolds numbers of 2000 to 3000 and testresults have confirmed that variation in pressure is linear for Reynoldsnumbers above approximately 20,000. While best results are obtained forReynolds numbers above 20,000, results have been obtained for Reynoldsnumbers in the range of 5000. The pressure turbulence ofa liquid is to100 times that of gas flow, thus the device is relatively insensitive togas flow. While the accuracy of the system is in the neighborhood ofplus or minus 10%, this is satisfactory for many operations. This isespecially the case where the information is used to improve theproduction efficiency of an oil well and is not relied upon fordetermining the actual production of the wells for accounting purposes.

The apparatus used in practicing the invention consists of apiezoelectric dynamic pressure transducer, a circuit for converting theelectrical signal from the transducer to a RMS signal and an integratingnetwork for integrating the RMS signal. The pressure transducer respondsto fluctuations above approximately 1 Hz and does not respond to staticpressure or slow changes in line pressure. vibrations. or temperature.Thus. the transducer produces an output signal only when aliquid slugpasses the transducer and does not appreciably respond to gas flow. TheRMS signal is related to the actual energy in the signal which can beused to determine the total liquid flow and one only needs to integratethe RMS signal over a time period to obtain an indication of the totalflow from the well.

The signal from the circuit indicating total flow can be used foradjusting the gas flow in a gas lift well or the length of the pumpingperiods in a pumped well. Of course, it is also possible to use thesystem for measuring the flow of water into an injection or disposalwell. Normally, injection wells are designed for a certain flow rate anda change in this flow rate indicates either a change in the reservoirinto which the water is injected or a breakdown in the injectionequipment at the surface.

. BRIEF DESCRIPTION OF THE DRAWINGS The present invention will be moreeasily understood from the following detailed description taken inconjunction with the attached drawings in which:

FIG. 1 is a blocked diagram of the apparatus used for practicing themethod;

FIG. 2 is a plot of the total RMS energy versus Reynolds numbers;

FIG. 3 is a plot of the RMS energy versus various frequencies;

FIG. 4 shows the actual signal produced by the transducer and thecorresponding RMS signal;

FIG. 5 is: a signal from a second well showing the transducer signal andthe RMS signal;

FIG. 6' shows the'same well as in FIG. 5 but the well has been pumpedoff and there is no liquid flow;

FIG. 7 shows the relationship between liquid production and the RMSsignal; and

FIG. 8 shows the relationship between liquid production and the RMSsignal for a separate set of values.

DESCRIPTION OF THE PREFERRED EMBODIMENTS Referring now to FIG. 1. thereis shown a block diagram of a system suitable for practicing the methodof this invention. There is shown afluid production line 10 which can bethe production line from an oil well under some manner of artificiallift as, for example, a gaslift, a rod pump well, a hydraulically pumpedwell, or submersible pumped well. The production line 10 can also be theinjection line well. While the above terms "oil well" is used tosimplify the description of the invention, the invention is adaptable toany well having turbulent slug or two-phase flow and is not limited to aconventional oil well where the gas to liquid ratio is in the range of lto 100.

A pressure transducer 11 is mounted on the production line 10 to sensechanges in the pressure of the liquid flowing in the line. The pressuretransducer may be mounted in a conventional sample port on the line anddoes not project into the interior of the line. In oil fieldinstallations, it is desirable to maintain production lines free ofobstructions so that through-the-flowline tools may be circulated. Ofcourse, pressure changes will only occur when there is turbulent flow inthe line. When the fluid flow occurs at Reynolds numbers below 20,000,the fluid flow measured by the invention will not be linear and thesystem must be calibrated. Likewise. in case of gas flow where pressurechanges are very small, the pressure transducer will not sense thechange. Any dynamic type of pressure transducer that supplies anelectric signal related to the instantaneous changes in the pressure canbe used. For example. a transducer sold under the name Kistler Model 205H-l manufactured by the Kistler Instrument Company of Redmond,Washington. can be used. Similar piezoelectric transducers,magnetostrictive transducers. or magneto electric transducers could alsobe used. The dynamic pressure transducer is mounted in a port formed inthe wall of the production line 10. Since the transducer responses todynamic pressure changes. it need not project into the production line.Thus, through-theflowline tools may be passed through the productionline without removing the transducer. The electrical signal from thetransducer is supplied to a coupling device 13 which may be a part ofthe transducer itself with the coupling device being connected by acoaxial cable 14 to a RMS conversion circuit 15. The coupling device 13matches the high impedance signal from the transducer to the inputcircuit ofthe root means square or RMS conversion circuit 15. The RMScircuit may be a traditional volt meter which converts a fluctuatingvoltage to an RMS signal. The RMS circuit is connected by a lead 17 toan integrator 18 whose output signal is recorded on a strip chartrecorder 19.

The above system can be fabricated from commercially available parts ora specially designed system can be used. The data collected on the stripchart recorder I9 can either be analyzed in the field visually or can betransmitted in the form of digital or analog data to a central locationwhere it can be analyzed in more detail or by sophisticated analysis.Likewise. the signal from the integrator 18 can be supplied to a simplecomputer which in turn controls the lift mechanism for the well. Forexample, the computer may consist of a conventional process controller20 whose set point 2] is adjusted for the optimum liquid production fromthe well and whose output controls the lift mechanism. Of course. in thecase of a mechanically pumped well. the set point could be adjusted fora minimum liquid flow and when the actual liquid flow from the wellfalls below the set point. the process controller would secure thepumping unit for a predetermined time interval to allow the well tofill. The output signal from the process controller 20 is used tocontrol the operation of the artificial lift control 22. The artificiallift control may be the power switch for a pump unit on the flow controlfor the gas supply in a gas lift well.

Referring to FIG. 2, there is shown a plot of the value of the RMSsignal versus various Reynolds numbers. As can be seen in the range ofReynolds numbers of 20,000 and greater, the RMS signal is substantiallylinear. Thus, one can use the RMS signal as a measure of liquid flow. Ofcourse. the actual liquid flow in volumetric measurement will be equalto the RMS signal times a constant wherein the constant is related tothe density of the liquid and the size of the pipeline.

FIG. 3 illustrates the relationship between the RMS energy in the signaland the various frequencies of the signal. As can be seen atapproximately Hz. there is a large difference between the flow ratescorresponding to Reynolds numbers of 20,000 to 50.000. Thus. it ispossible to accurately determine the fluid flow in the flowline from thevariations in the energy level of the RMS signal.

Referring now to FIG. 4. there is shown a portion of a signal from a gaslift well wherein the signal A represents the signal produced by thetransducer while the signal B shows the RMS signal. In addition. thereis shown the time interval of 1 second. If one integrates the RMSsignal. one will obtain the total flow from the well. Also. one cancount the times that the RMS signal has values above the base line whichindicate the number of slugs of liquid passing through the productionflowline. From this information one can determine whether the gas flowshould be increased or decreased.

FIG. 5 illustrates signals similar to those shown in FIG. 4 but for awell having a high flow rate. As can be seen in signal B of FIG. 4, thepressure pulsations are almost continuous and the intervals between theslugs ofliquid and the gas slugs are considerably shorter. Still it ispossible to count the slugs of liquid and take appropriate action.

FIG. 6 illustrates the same well as shown in FIG, 5 but for thecondition where substantially all the liquid has been removed from thereservoir. In this condition, there is substantially no liquid and RMSsignal is substantially zero. This would indicate substantially zeroproduction from the well. While the RMS signal does have slightamplitude excursions. the total integrated area of the signals would bewell within the plus or minus 10% accuracy of the instrument. Asexplained in the introduction, this accuracy is within the requirementsfor controlling the production of the average oil well.

FIGS. 7 and 8 illustrate the relationship between the RMS signal outputin millivolts and the production of liquids. i.e.. oil plus water inbarrels per day. From these figures, one can correlate the data recordedon the strip chart recorder of FIG. I to obtain an actual reading inbarrels of liquid per day.

We claim as our invention:

1. A method for controlling the operation of an artificially lifted oilwell comprising:

measuring at the surface fluctuations in the pressure of the fluid flowfrom the well;

measuring the RMS value of the fluctuations;

integrating the RMS signal occurring in a predetermined time period toobtain a signal related to the liquid flow from the well; comparing saidintegrated signal with a pre-set signal representing the desired liquidflow from the well over the time period to obtain an error signal; and

controlling the artificial lift means in response to said error signal.

2. The method of claim 1 wherein the well is a gas lift well and thequantity of gas injected into the well is controlled.

3. The method of claim 1 wherein the well is a rod pumped well and theon and off cycle of the pump is controlled.

1. A method for controlling the operation of an artificially lifted oilwell comprising: measuring at the surface fluctuations in the pressureof the fluid flow from the well; measuring the RMS value of thefluctuations; integrating the RMS signal occurring in a predeterminedtime period to obtain a signal related to the liquid flow from the well;comparing said integrated signal with a pre-set signal representing thedesired liquid flow from the well over the time period to obtain anerror signal; and controlling the aritificial lift means in response tosaid error signal.
 2. The method of claim 1 wherein the well is a gaslift well and the quantity of gas injected into the well is controlled.3. The method of claim 1 wherein the well is a rod pumped well and theon and off cycle of the pump is controlled.